Raj143 You pose a difficult question, as there are a number of...

Raj143
You pose a difficult question, as there are a number of unknowns.
Frack design, 88e have not specified this, other than to say it is a vertical. I know there has been data exchange with PANR on well data from Talitha A, located 2.8 miles North, but more importantly 9.3 miles distant as the crow flies.
It is mutually beneficial for both PANR and 88e to learn from each others fracking experience, but there has been no formal agreement on this, so possibly no learnings transferred from PANRs latest success. Even so, it is public knowledge, that PANR used 11000 bbls of water and 400000 lbs of 100 mesh sand, in the flow test of the SMDB reservoir, at Alkaid 2 (~16 miles North)
This sets a standard against which 88e results can be measured, if 88e have used a similar frack design and it proves to achieve the 50% fracture efficiency of PANRs Alkaid 2 SMDB test, then any variation is reservoir or flow rate specific.
PANR achieved a range of 30 to 100 bpd of oil, with an average of 45 bpd over 5 days of oil flow, subsequent analysis has added 20 to 40 bpd of natural gas liquids to these numbers. Note this was an 11 day flow test, the first 6 in clean up, followed by 5 of oil flow, 88e are running much shorter flow tests of only 4 days including clean up. Which implies an aggressive flow plan, or much smaller fracture. PANR went gently to avoid high gas exsolution from the oil. It is another variable to consider, is the flow test going to be aggressive but unsustainable? with a high initial flow, but rapid decline, that will not show in a short test
Summarizing there are three variable factors, frack size, frack efficiency, and flow plan. All of these would need to be aligned with the PANR flow test to be a meaningful comparison. Frack size has not been announced, frack efficiency MAY be announced post flow test, the flow test timeline implies an aggressive flow test that may not be as reliable an indication of performance.
In any case a costly full horizontal drill, multistage stimulation and long term flow test will be required, as a follow up to prove commerciality, this years tests are a step on the path towards proof.

Beyond that it is important to be clear on what is being tested and the expectations on volume of oil.
There are two zones being tested.
The newly encountered upper SFS, at present there is no estimated volume associated with this target. I would not expect it be as large as the lower SFS estimate of net best of 84mmbo, as it did not show in the previous seismic, but for the sake of argument assume a generous 84mmbo.

Then there is the SMDB reservoir, all up the sum of SMDs A + B + C is estimated at net best of 140mmbo. In breaking this down refer to page 17 (December 2022 presentation) https://clients3.weblink.com.au/pdf/88E/02612833.pdf
in which SMDB is allocated 80 production wells, with SMDA and C having a combined 196, so giving 29% of the SMDs within the SMDB reservoir. Worked through that gives a estimated target of 41mmbo for the SMDB being tested.
Over both the SFS and SMDB it is a quite modest 125mmbo in the success case.
Then bear in mind these are down dip reservoirs at greater risk of reduced flow rates, due to compaction and composition, the SMDB is around 1000 ft deeper, plus DMAX adding about another 1000 ft of effective burial depth.
https://clients3.weblink.com.au/pdf/88E/02508470.pdf Pg3